Mobile Pump System

ABSTRACT

A mobile pump system includes: a trailer movable by a vehicle; and a pump mounted to the trailer, the pump configured to pump a fluid. The pump includes an electrically-driven motor mounted to the trailer or is turbine powered by a turbine mounted to the trailer. A method for performing a pressure pumping application is also disclosed.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Provisional Patent Application No. 62/666,945, filed May 4, 2018, the disclosure of which is hereby incorporated in its entirety by reference.

BACKGROUND Field

The present disclosure relates to a mobile pump system and a method for performing a pressure pumping application.

Technical Considerations

Pressure pumping includes a propagation of fractures through layers of rock using pressurized fluid and/or pumping cement into a wellbore to complete it.

In one non-limiting example of pressure pumping, to extract oil and/or gas trapped in formations beneath the Earth's surface, drilling of a wellbore is required, and the oil and/or gas may be recovered and extracted through the wellbore. Various pumps may be used during the drilling and oil and/or gas recovery process.

In some non-limiting oilfield applications, drilling may include forming horizontal laterals extending out from a vertical section of the wellbore. The formation defining the vertical or lateral section may be fractured in sections, such that a fracture stimulation treatment is completed in the first section before moving on to apply a fracture stimulation treatment on a second section. This may be performed using a plug-and-perf technique in which a perforating gun is used to initiate fractures in the formation in the section after a plug is positioned between the first section and the second section. The plug seals the first section of the lateral from the other sections. This plug-and-perf technique is repeated for each section of the lateral until all intended sections of the lateral are perforated and fracture stimulated.

The plug may be positioned at a predetermined location along the lateral by utilizing a pump system to pump a fluid into the wellbore, which exerts a pressure on the plug. The pressure on the plug moves the plug along the lateral to the desired position. Positioning the plug using the pump is considered an ancillary application, commonly referred to as “pumpdown”.

Existing pumps used in pressure pumping application, such as in ancillary pumpdown applications have numerous drawbacks. For example, existing pumps use an internal combustion engine driven by diesel fuel, which have high carbon footprints. In addition, these existing pumps are cumbersome and require considerable room at the well site. Further, these existing pumps do not allow for sufficiently precise control of flow rate, making it difficult to move the plug to the desired position. Existing pumps are expensive to acquire and maintain, and they create significant noise at a decibel level that is known to harm human hearing without adequate ear protection.

Further, existing pumping systems utilized in pressure pumping applications, including ancillary pressure pumping applications, are not capable of sufficiently low flow rates or precise control of the flow rate. The existing pump systems lack precise control and the ability to operate at lower flow rates because they utilize conventional transmissions that are incapable of smooth increase or decrease in pumping rates. This may be the result of hesitation and slugging common when primary gears disengage and engage the secondary shaft. As a result, existing pressure pumping systems do not effectively remedy screen outs occurring during hydraulic fracturing applications.

Therefore, a pump suitable for pressure pumping applications that overcomes some or all of the disadvantages of existing pumps is desired.

SUMMARY

The present disclosure is directed to a mobile pump system including: a trailer movable by a vehicle; and a pump mounted to the trailer, the pump configured to pump a fluid. The pump includes an electrically-driven motor mounted to the trailer or is turbine powered by a turbine mounted to the trailer.

The pump may be configured to pump the fluid into a wellbore at a tie-in point upstream of a wellhead of the wellbore. The fluid may include water and/or a chemical additive. The pump may include an auger or impeller configured to move the fluid. The pump may not be permanently installed at a site for performing a pressure pumping application. The electrically-driven motor may be fueled by a battery, natural gas, diesel fuel, or gasoline. The pump may be configured to adjust a flow rate of the pump by 1/10th of a bpm. The pump may be in fluid communication with a wellbore. The turbine may be operated using field gas. The mobile pump system may include plurality of pumps mounted to the trailer, where each pump may include an electrically-driven motor mounted to the trailer or may be turbine powered by a turbine mounted on the trailer. The mobile pump system may include controller configured to remotely control the pump. The controller may include a portable computing device. The pump may be configured to pump the fluid at a flow rate as low as 0.1 bpm. The turbine may include a direct coupled gear connection.

The present disclosure is also directed to a method for performing a pressure pumping application including: providing a mobile pump system including: a trailer movable by a vehicle; and a pump mounted to the trailer, the pump configured to pump a fluid, where the pump includes an electrically-driven motor mounted to the trailer or is turbine powered by a turbine mounted to the trailer.

The method may include pumping the fluid from a fluid container into a wellbore using the pump to move the fluid from the fluid container into the wellbore. The method may include positioning a plug in a lateral of the wellbore using the fluid pumped into the wellbore. The pump may be configured to pump the fluid into the wellbore at a tie-in point upstream of a wellhead of the wellbore. The fluid may include water and/or a chemical additive. The pump may include an auger or impeller configured to move the fluid. The pump may not be permanently installed at a site for performing a pressure pumping application. The electrically-driven motor may be fueled by a battery, natural gas, diesel fuel, or gasoline. The pump may be configured to adjust a flow rate by 1/10th of a bpm. The pump may be in fluid communication with a wellbore. The turbine may be operated using field gas. The pump may be configured to pump the fluid at a flow rate as low as 0.1 bpm. The pump may be remotely controlled by a controller. The controller may include a portable computing device. The pump may be configured to pump the fluid at a flow rate of up to 140 barrels per minute (bpm) at a pressure of up to 20,000 psi.

Further embodiments are set forth in the following numbered clauses:

Clause 1: A mobile pump system comprising: a trailer movable by a vehicle; and a pump mounted to the trailer, the pump configured to pump a fluid, wherein the pump comprises an electrically-driven motor mounted to the trailer or is turbine powered by a turbine mounted to the trailer.

Clause 2: The mobile pump system of clause 1, wherein the pump is configured to pump the fluid into a wellbore at a tie-in point upstream of a wellhead of the wellbore.

Clause 3: The mobile pump system of clause 1 or 2, wherein the fluid comprises water and/or a chemical additive.

Clause 4: The mobile pump system of any of clauses 1-3, wherein the pump comprises an auger or impeller configured to move the fluid.

Clause 5: The mobile pump system of any of clauses 1-4, wherein the pump is not permanently installed at a site for performing a pressure pumping application.

Clause 6: The mobile pump system of any of clauses 1-5, wherein the electrically-driven motor is fueled by a battery, natural gas, diesel fuel, or gasoline.

Clause 7: The mobile pump system of any of clauses 2-6, wherein the pump is configured to adjust a flow rate of the pump by 1/10th of a bpm.

Clause 8: The mobile pump system of any of clauses 1-7, wherein the pump is in fluid communication with a wellbore.

Clause 9: The mobile pump system of any of clauses 1-8, wherein the turbine is operated using field gas.

Clause 10: The mobile pump system of any of clauses 1-9, comprising a plurality of pumps mounted to the trailer, wherein each pump comprises an electrically-driven motor mounted to the trailer or is turbine powered by a turbine mounted on the trailer.

Clause 11: The mobile pump system of any of clauses 1-10, further comprising a controller configured to remotely control the pump.

Clause 12: The mobile pump system of clause 11, wherein the controller comprises a portable computing device.

Clause 13: The mobile pump system of any of clauses 1-12, wherein the pump is configured to pump the fluid at a flow rate as low as 0.1 bpm.

Clause 14: The mobile pump system of any of clauses 1-13, wherein the turbine comprises a direct coupled gear connection.

Clause 15: The mobile pump system of any of clauses 1-14, wherein the pump is configured to pump the fluid at a flow rate of up to 140 barrels per minute (bpm) at a pressure of up to 20,000 psi.

Clause 16: A method for performing a pressure pumping application comprising: providing a mobile pump system comprising: a trailer movable by a vehicle; and a pump mounted to the trailer, the pump configured to pump a fluid, wherein the pump comprises an electrically-driven motor mounted to the trailer or is turbine powered by a turbine mounted to the trailer.

Clause 17: The method of clause 16, further comprising: pumping the fluid from a fluid container into a wellbore using the pump to move the fluid from the fluid container into the wellbore.

Clause 18: The method of clause 17, further comprising: positioning a plug in a lateral of the wellbore using the fluid pumped into the wellbore.

Clause 19: The method of any of clauses 16-18, wherein the pump is configured to pump the fluid into the wellbore at a tie-in point upstream of a wellhead of the wellbore.

Clause 20: The method of any of clauses 16-19, wherein the fluid comprises water and/or a chemical additive.

Clause 21: The method of any of clauses 16-20, wherein the pump comprises an auger or impeller configured to move the fluid.

Clause 22: The method of any of clauses 16-21, wherein the pump is not permanently installed at a site for performing a pressure pumping application.

Clause 23: The method of any of clauses 16-22, wherein the electrically-driven motor is fueled by a battery, natural gas, diesel fuel, or gasoline.

Clause 24: The method of any of clauses 16-23, wherein the pump is configured to adjust a flow rate by 1/10th of a bpm.

Clause 25: The method of any of clauses 16-24, wherein the pump is in fluid communication with a wellbore.

Clause 26: The method of any of clauses 16-25, wherein the turbine is operated using field gas.

Clause 27: The method of any of clauses 16-26, wherein the pump is configured to pump the fluid at a flow rate as low as 0.1 bpm.

Clause 28: The method of any of clauses 16-27, wherein the pump is remotely controlled by a controller.

Clause 29: The method of clause 28, wherein the controller comprises a portable computing device.

Clause 30: The method of any of clauses 16-29, wherein the pump is configured to pump the fluid at a flow rate of up to 140 barrels per minute (bpm) at a pressure of up to 20,000 psi.

BRIEF DESCRIPTION OF THE DRAWINGS

Additional advantages and details are explained in greater detail below with reference to the exemplary embodiments that are illustrated in the accompanying schematic figures, in which:

FIG. 1 shows a schematic cross-sectional view of the Earth at an oil and/or gas production site utilizing horizontal drilling techniques;

FIG. 2 shows another schematic cross-sectional view of the Earth at an oil and/or gas production site utilizing horizontal drilling techniques and a mobile pump system;

FIG. 3 shows a schematic aerial view of a well pad at an oil and/or gas production site, the well pad including a mobile pump system;

FIG. 4 shows a schematic side view of a mobile pump system according having a trailer and a cab for moving the mobile pump system;

FIG. 5 shows a schematic top view of a mobile pump system including the trailer and the electrically-driven pump or turbine-driven pump

FIG. 6 shows a schematic side view of an auger-style pump of a mobile pump system;

FIG. 7 shows a controller for controlling a mobile pump system; and

FIG. 8 shows a schematic top view of a mobile pump system including a pump driven by an electric motor;

FIG. 9 shows a schematic perspective view of a mobile pump system including a pump driven by a turbine;

FIG. 10 shows a schematic perspective view of a mobile pump system including a pump driven by a turbine, with the trailer including a fuel tank; and

FIG. 11 shows a schematic top view of a mobile pump system including a secondary pump.

DETAILED DESCRIPTION

For purposes of the description hereinafter, the terms “end,” “upper,” “lower,” “right,” “left,” “vertical,” “horizontal,” “top,” “bottom,” “lateral,” “longitudinal,” and derivatives thereof shall relate to the invention as it is oriented in the drawing figures. However, it is to be understood that the invention may assume various alternative variations and step sequences, except where expressly specified to the contrary. It is also to be understood that the specific devices and processes illustrated in the attached drawings, and described in the following specification, are simply exemplary embodiments or aspects of the invention. Hence, specific dimensions and other physical characteristics related to the embodiments or aspects disclosed herein are not to be considered as limiting.

The present disclosure is directed to a mobile pump system that includes: a trailer movable by a vehicle; and a pump mounted to the trailer, the pump configured to pump a fluid, wherein the pump comprises an electrically-driven motor mounted to the trailer or is turbine powered by a turbine mounted to the trailer. The mobile pump system described herein may be suitable for pressure pumping applications.

Referring to FIG. 1, an oil and/or gas production site 10 is shown. At the production site 10, the surface 11 (Earth's surface) includes wellbore 12 created by drilling. The wellbore 12 includes a wellhead 13, which is a structural component at the surface 11 of the wellbore 12 which provides a structural and pressure-containing interface for various drilling and production equipment. The production site 10 may be a site for conducting hydraulic fracturing.

With continued reference to FIG. 1, the production site 10 may utilize a horizontal drilling technique in which at least one lateral 14 is used. For the horizontal drilling technique, the wellbore 12 may include a vertical region of 2,500 to 25,000, such as 6,000 to 15,000 or 6,000 to 10,000 feet in depth, although the length of this vertical region is not limited to this range. The wellbore 12 may include a leveling-off point 16 in which the vertical region ends and the lateral 14 is drilled horizontally in the Earth (the lateral 14 may have approximately the same depth from the surface 11 at all points). Each lateral 14 may have a length of 2,500-25,000, such as 3,000 to 10,000 feet, as measured from the leveling-off point 16 to an end 18 of the lateral 14, although the length of the lateral 14 is not limited to this range. It will be appreciated that FIG. 1 is not drawn to scale, but merely provides a useful schematic of a production site 10 performing horizontal drilling.

The lateral 14 may include a plurality of regions, which are of a predetermined length. Hydraulic fracture stimulation treatment may be performed in the lateral 14 individually at each region. Hydraulic fracture stimulation treatment includes pumping a fracturing fluid into the formation. The lateral 14 of the schematic in FIG. 1 includes a first region 20, a second region 22, a third region 24, a fourth region 26, a fifth region 28, and a sixth region 30.

With continued reference to FIG. 1, the production site 10 may utilize a “plug-and-perf” method for hydraulic fracture stimulation treatment. In FIG. 1, hydraulic fracture stimulation treatment has been completed for the first region 20. A fractured first region 32 was created in the formation at the first region 20. After the hydraulic fracture stimulation treatment was completed in the first region 20, a first plug 34 was positioned at an end of the first region 20 closest to the wellhead 13 (a proximal end of the first region 20). Once in place, this first plug 34 may prevent fluid subsequently pumped into the wellbore 12 from entering the first region 20.

With continued reference to FIG. 1, hydraulic fracture stimulation treatment in the second region 22 of the formation may be initiated by lowering a perforating gun 36 (hereinafter “perf gun”) into the wellbore 12 and positioning the perf gun 36 in the second region 22. The perf gun 36 may be lowered into the wellbore 12 using a perf trailer 37. Once positioned correctly, charges of the perf gun 36 may be detonated so as to create multiple connection points from the wellbore 12 to the formation in the second region 22. Oil and/or gas may be extracted by escaping from fractures and extracted to the surface 11 via the wellbore 12.

Referring to FIG. 2, the production site 10 is shown at a time after that depicted in FIG. 1. The fractured second region 38 is shown, which was created by the perf gun 36 from FIG. 1. It will be appreciated that FIG. 2 is also not drawn to scale, but merely provides a useful schematic of a production site 10 performing horizontal and/or vertical drilling.

In FIG. 2, a second plug 40 is being lowered into the wellbore 12 by a plug trailer 41 to be positioned at a proximal position of the second region 22 (on the end of the second region 22 closer to the wellhead 13). The second plug 40 is spaced apart from the first plug 34 by approximately the length of the second region 22. The second plug 40 may be positioned using positioning fluid 42 to provide pressure to the second plug 40 to move the second plug along the length of the wellbore 12 (including the lateral 14). The positioning fluid 42 may include water and/or a chemical additive. The chemical additive may include a friction reducer to reduce surface tension. The chemical additive may reduce tension or pipe friction along the wellbore 12 associated with positioning the second plug 40.

The second plug 40 may be positioned using the mobile pump system 44 of the present disclosure. The mobile pump system 44 may be used to position the second plug 40 as merely one non-limiting example of how the mobile pump system 44 may be used in a pressure pumping application. However, it will be appreciated that the mobile pump system 44 may be used to complete other pressure pumping applications using the components of the mobile pump system 44 described hereinafter.

The mobile pump system 44 may include a trailer 46 movable by a vehicle (e.g., a cab having a fifth wheel). The trailer 46 may be movable by a vehicle, such as a cab, to and from the production site 10. In this way, the mobile pump system 44 may be conveniently moved from location to location, such as to and from the production site 10, and the mobile pump system 44 does not need to be permanently installed at the production site 10. The trailer 46 may be separable/detachable from the vehicle such that the trailer 46 may be left at the production site 10 and the vehicle driven away, or the trailer 46 may be integrated with the vehicle, such that the vehicle remains at the production site 10 while the mobile pump system 44 is in use and drives away after use of the mobile pump system 44 is completed.

With continued reference to FIG. 2, the mobile pump system 44 may further include a pump 48 mounted to the trailer 46. The pump 48 may be configured to pump the positioning fluid 42 into the wellbore 12. The pump may include an electric motor 50 mounted to the trailer 46 or may be powered by a turbine 50 mounted to the trailer 46. The trailer 46 may include multiple pumps 48 in some embodiments and may include multiple electric motors or turbines 50 for driving the pumps 48. As used herein, the term “electric motor” or “electrically-driven motor” refers to a motor in which electrical energy is converted into mechanical energy. As used herein, the term “turbine” refers to a rotary mechanical device that extracts energy from a fluid (e.g., liquid and/or gas) flow and converts it into useful work to generate electrical energy to power the pump 48. The trailer 46 may also include a power generator 52 in connection with the pump 48 to fuel the electrically-driven motor or the turbine 50 of the pump 48. The power generator 52 may be battery, natural gas, diesel fuel, or gasoline fueled. The pump 48 may be driven by the electric motor or the turbine 50 and not by an internal combustion engine.

The pump 48 may be configured to pump the positioning fluid 42, or any other fluid, at a flow rate of up to 60 barrels per minute (bpm), such as up to 80 bpm, up to 100 bpm, up to 120 bpm, up to 140 bpm or higher. A barrel is defined as 42 US gallons, which is approximately 159 Liters. The pump 48 may be configured to pump the positioning fluid 42 at far lower flow rates, and may pump the positioning fluid 42 at a flow rate as low as 0.1 bpm (when the pump is not turned off such that it's flow rate would be 0 bpm). The pump 48 may be controlled such that its flow rate may be controlled within 1/10th of a bpm, resulting in a flow rate within 1/10th of a bpm compared to a predetermined flow rate. The pump may be configured to adjust the flow rate by 1/10th of a bpm (e.g., adjust the flow rate of the pump 48 from 60.0 bpm to 59.9 bpm or from 0.2 bpm to 0.1 bpm). Existing pressure pumping systems, including ancillary pressure pumping applications, are not capable of such low flow rates or such precise control of the flow rate. The existing pump systems lack precise control and the ability to operate at lower flow rates because they utilize conventional transmissions that are incapable of smooth increase or decrease in pumping rates. This may be the result of hesitation and slugging common when primary gears disengage and engage the secondary shaft.

The ability to pump at lower rates and to more precisely control the flow rate of the pump 48 may be especially useful in post-occurrence remedying of “screen outs,” which are common in hydraulic fracturing applications. A screen out occurs when proppant and fluid (of the positioning fluid 42, for example) can no longer be injected into the formation. This may be due to resistant stresses of the formation becoming too excessive or surface-originated reasons resulting in loss of viscosity to carry proppant so that it falls out of suspension and plugs perforations in the wellbore 12. In this way, the wellbore 12 becomes “packed” with proppant, which does not allow any further operations to continue due to high pressures that cannot be overcome from these blockages.

In response to screen outs, the wellbore 12 may be opened at the surface 11 to relieve pressure and to carry at least some of the proppant out of the wellbore 12 and create a pathway to continue fluid injection to clear the wellbore 12 and allow operations to continue, which is a dangerous operation. An attempt to continue pumping operations at low rates to avoid reaching maximum pressure so that the proppant that is packed is forced through perforations and into the wellbore 12 may be attempted. However, due to the limitations of existing pumps with conventional engines and transmissions, the pump cannot pump at low enough rates to avoid again reaching maximum pressure. As a result, existing systems are often required to switch to a coiled tubing procedure to wash the proppant out and carry it back to the surface so that the wellbore 12 is finally clear. The coiled tubing procedure results in shutdown of operations for 3-4 days and is additionally expensive to complete.

In contrast, existing systems are able to overcome these screen outs successfully without reverting to the coiled tubing procedure because the electric motor or the turbine 50 of the pump 48 allows the pump 48 to inject fluid for displacement at lower rates (as low as 0.1 bpm) over the course of hours or days without the risks posed by existing systems.

The ability to pump fluids at lower rates and to more precisely control the flow rate of the pump 48 may be especially useful in prevention or mitigation of the adiabatic effect which can cause wireline cable melting and/or failure during pump down operations, which are common in hydraulic fracturing applications. On pump downs and related jobs involving wireline operations with pump assist, the wellhead is equipped with a lubricator and flow tubes to enable operations in a wellbore that can have pressure of several thousand pounds or more of pressure. The process of bringing the lubricator and the wellbore to the same pressure is known as “equalization.” When the air in the lubricator compresses faster than it can be evacuated, the adiabatic compression can cause the temperature to rise to as much as 1,200° F. (−650° C.). At high temperatures, the insulating material of the cable would melt and the metallurgy of the steel in the cable would change, causing the actual wire in the wireline to become brittle and break, even to the point of severing the wireline within the lubricator. A common name for this condition is “wireline burn up” though other colloquialisms and phrases (such as “E-line burn”) describe the same condition.

In practice, to avoid wireline burn-up, the lubricator may first be filled with fluid prior to equalizing; this practice can mitigate much of the air and therefore most of the energy to cause damage. In order to fill the lubricator with fluid without inducing wireline burn-up, the fluid must be introduced at very low rates so that the air can be evacuated at an equivalent rate so as not to introduce temperature increases caused by compressing air rapidly. However, due to the limitations of existing pump systems with conventional engines and transmissions, the pump cannot pump at low enough rates to completely avoid against reaching damaging high temperatures. In contrast, the pump 48 would be able to overcome this situation successfully because the electric motor or the turbine 50 of the pump 48 allows the pump 48 to inject fluid for displacement of the air in the lubricator at lower rates (as low as approximately 0.1 bpm) without the risks posed by existing systems.

The pump 48 may be configured to pump fluid at a pressure of up to 20,000 psi, such as up to 15,000 psi, up to 12,000 psi, up to 10,000 psi, up to 8,000 psi, or up to 6,000 psi, although higher pressures are also contemplated.

With continued reference to FIG. 2, a fluid tank 54 containing the positioning fluid 42 may be in fluid communication with the pump 48. The pump 48 may pump the positioning fluid 42 from the fluid tank 54 into the wellbore 12 to position the second plug 40 at a predetermined position in the wellbore 12.

With continued reference to FIG. 2, the mobile pump system 44 may position the second plug 40 at a predetermined position in the wellbore 12. The second plug 40 may be positioned in the wellbore by providing the previously-described mobile pump system 44. The pump 48 of the mobile pump system 44 may be placed in fluid communication with the wellbore 12. The positioning fluid 42 may be pumped from the fluid tank 54 into the wellbore 12 using the pump 48. The positioning fluid 42 pumped into the wellbore 12 may exert a pressure on the second plug 40 so as to move the second plug 40 along the lateral 14 and into the predetermined position. The position of the second plug 40 may be monitored from the surface by any means known in the art. The flow rate of the positioning fluid 42 pumped by the pump 48 may be adjusted and controlled to position the second plug 40. The flow rate may be increased or decreased to adjust the rate at which the second plug 40 is moved. For example, when the second plug 40 is proximate the predetermined position, the flow rate of positioning fluid 42 may be lowered so that the position of the second plug 40 can be more precisely selected.

The mobile pump system 44 described herein may be used for any pressure pumping in which its characteristics are suitable and is not limited to the above-described application. For example, the mobile pump system 44 may be used in hydraulic fracturing applications. Hydraulic fracturing applications include any application associated with hydraulic fracturing performed at a production site. Hydraulic fracturing refers to fluid injected down the wellbore through perforations exceeding the minimum fracture pressure needed to fracture the rock in the formation. An example of a hydraulic fracturing application includes ancillary applications (“pumpdown”), such as positioning a plug (previously described), drillout applications, injecting acid into the formation, pressure testing casing, injecting diverter materials, “toe preps” involving initiating the first fracture network in a well, and the like. Drillout applications may include applications performed after the drilling and fracturing process has concluded and the well is being prepared to deliver hydrocarbon production. As one example, a drillout application may include milling or drilling out plugs previously positioned in the laterals and removing debris from the milled plugs by pumping the debris from the plug location to the surface.

The mobile pump system 44 allows for the reduction of capital costs compared to existing pump systems as the mobile pump system 44 requires less capital costs to build and operate. The mobile pump system 44 also significantly reduces repair and maintenance costs compared to existing systems. The use of the electric motor or turbine 50 to drive the pump 48 helps to reduce repair and maintenance costs. The electric motor or turbine 50 has a higher run time before requiring repairs compared to conventional internal combustion engines (motors) used in existing pumps, which are diesel driven, for example. Keeping the electric motor or turbine 50 cool and lubricated allows the electric motor or turbine 50 to have a longer running life compared to the motors used in existing systems. The electric motor or turbine 50 also run more efficiently compared to the motors used in existing systems, such as in terms of emissions and consumption of fuel.

The mobile pump system 44 using the electric motor or turbine 50 to drive the pump 48 also requires significantly less fuel compared to existing systems. The electric motor or turbine 50 may utilize natural gas powered electric generation, such as the field gas available at a production site. Thus, sulfur and other pollutants that arise from diesel combustion in conventional internal combustion motors are not present in the combustion of natural gas powered electric generation. The inclusion of the electric motor or the turbine 50 in the mobile pump system 44 also reduces the noise associated with the mobile pump system 44 as pumps used in existing systems provide significant noise pollution and make it difficult to operate such pumps in residential areas (e.g., near housing plans, schools, hospitals, and the like).

The mobile pump system 44 includes a more compact design of the pumps 48 compared with existing systems. Multiple pumps 48 may be included on the trailer 46. The more compact system contributes to a safe production site 10 as there are less components at the production site 10 to cause a navigational and/or tripping hazard. This compact design also allows for the mobile pump system 44 to be set-up faster, resulting in less wasted time and faster time to production. Moreover, the mobile pump system 44 may include multiple of at least on component included in the system, such as multiple pumps 48, multiple electric motors or turbines 50, multiple controllers 80, and the like. The redundancy associated with certain of the components mounted on the trailer 46 of the mobile pump system 44 allows the system to avoid stopping operation of the pressure pumping application should one of the redundant components fail.

Referring to FIG. 3, an aerial view of the production site 10 is shown. The production site 10 includes a well pad 56. The well pad 56 includes six wellbores 12A-12F, each wellbore having a vertical region and at least one lateral traversing a direction different from the other wellbores of the well pad 56. In the schematic in FIG. 3, the non-limiting example of a pressure pumping application is being conducted at only the first wellbore 12A; however, multiple well heads may be in production (e.g., conducting oilfield activity) simultaneously.

The production site 10 may include at least one fracturing trailer 58A-58F, each including at least one fracturing pump 60A-60F. The production site 10 may further include sand and fracturing fluid storage tanks 62, which include sand and fracturing fluid used to keep fractures in the formation open. The production site 10 may further include a water tank 64 for pumping water into the first wellbore 12A. The water tank 64 may be in addition to or the same as the fluid tank 54 containing the positioning fluid 42. The production site 10 may further include a chemical storage tank 66, which may store any useful chemical, such as a friction reducer (e.g., polyacrylamide or a guar-based chemical). The fracturing pumps 60A-60F may be in fluid communication with at least one of the sand and fracturing fluid storage tanks 62, the water tank 64, and the chemical storage tank 66 to pump the various materials and/or fluids contained therein into the first wellbore 12A via piping 70. The piping 70 may include an isolation valve 72 for isolating the fracturing pumps 60A-60F from the first wellbore 12A when the fracturing pumps 60A-60F are not pumping fluid/material into the first wellbore 12A.

With continued reference to FIG. 3, the production site 10 may further include a data monitoring station 68, which may be used to monitor all operations conducted at the production site 10 and control those operations accordingly. In some non-limiting examples, the data monitoring station 68 may be remote from the production site 10.

With continued reference to FIG. 3, production site 10 may further include the mobile pump system 44A. The production site may include a single mobile pump system 44A or multiple mobile pump systems 44A-44B, as necessary. In the non-limiting example of FIG. 3, a first mobile pumping system 44A is used to pump positioning fluid 42 into the first wellbore 12A. The first mobile pumping system 44A may include a first trailer 46A, a first power generator 52A, and a first pump 48A having a first electric motor 50A. The production site 10 may utilize a second mobile pumping system 44B in addition to or in lieu of the first mobile pumping system 44A. The second mobile pumping system 44B may include a second trailer 46B, a second power generator 52B, and two pumps 48B, 48C, each having an electric motor 50B, 50C. The production site 10 may include the fluid tank 54 containing the positioning fluid 42, and the fluid tank 54 may be in fluid communication with the first pump 48A of the first mobile pumping system 44A. The first mobile pumping system 44A and the second mobile pumping system 44B may be moved to and from the production site 10 without being permanently installed at the pumping site 10.

With continued reference to FIG. 3, the first pump 48A may be in fluid communication with the first wellbore 12A so as to pump the positioning fluid 42 into the first wellbore 12A. The first pump 48A may be in fluid communication with the piping 70 so as to be in fluid communication with the first wellbore 12A, and the first pump 48A may intersect with the piping 70 at a tie-in point 74. The tie-in point 74 may be upstream of the wellhead of the first wellbore 12A (e.g., before the piping 70 reaches the wellhead of the first wellbore 12A).

Referring to FIG. 4, a non-limiting example of the mobile pump system 44 may include a cab 76. The cab 76 may be a truck capable of attaching the trailer 46 thereto (such as via a fifth wheel), so that the trailer 46 may be hauled to and from the production site 10. The trailer 46 may be detachable from the cab 76 so that it may be left at the job site, or the trailer 46 may be an integrated part of the cab 76 (not detachable therefrom). In some examples, the cab 76 is the power generator 52 because the cab may fuel the electric motor or turbine 50 used to drive the pump 48.

Referring to FIG. 5, a top view of a non-limiting example of the mobile pump system 44 is shown, with the mobile pump system 44 including the trailer 46, the pump 48 having the electric motor 50, and the power generator 52. The power generator 52 may be connected to the pump 48 (e.g., the electric motor 50) to fuel the electric motor 50, such that the electric motor 50 may drive the pump 48.

Referring to FIG. 6, a non-limiting example of the pump 48 is shown. The pump 48 may be any pump suitable for pumping the positioning fluid 42 as previously described. In one example, the pump 48 may be an auger-style pump that includes an auger or impeller 78 driven by the electric motor or the turbine 50 to move the positioning fluid 42 into the wellbore 12. The auger-style pump may provide certain advantages, including allowing for a more precise control of flow rate, reduced maintenance, and ease of maintenance (based on the reduced number and simplicity of components).

Referring to FIG. 7, the pump 48, the electric motor or the turbine 50, the generator 52, and/or other components (“controllable components”) of the mobile pump system 44 may be controlled remotely by a controller 80. As used herein, “remotely” refers to a geographic location separate from the controllable component. The pump 48 may be controlled from the data monitoring station 68 or other location at the production site 10 (shown in FIG. 3), or the pump 48 may be controlled off-site (not at the production site 10). The pump 48 may be controlled by the controller 80 that is a portable computing device, such that the portable computing device may be moved between locations and is still able to control the pump 48. The portable computing device may be, for instance, a laptop computer, a tablet computer, or a smartphone. Thus, relevant data associated with the mobile pump system 44 may be communicated to the controller 80 remote from the controllable component(s).

An exemplary graphical user interface (GUI) displayed on the controller 80 is shown in FIG. 7, and a user may control the controllable components by interacting with the GUI on the controller 80. The GUI may allow the user to control various features of the controllable components. Non-limiting examples include controlling the pump's 48 flow rate or the pressure of the pump 48. The GUI may display the flow rate and pressure of the pump 48. The GUI may allow the user to turn the pump 48 on or off. The GUI may display the fill level of the fluid tank 54 or provide a status of the electric motor or the turbine 50, such as whether any issues are identified with the electric motor or the turbine. It will be appreciated that other aspects of the mobile pump system 44 may be controlled by interacting with the GUI, and any suitable layout of the GUI may be used. Multiple controllable components (e.g., multiple pumps) may be controllable from the same controller 80.

Beyond providing the capability to adjust certain parameters of the system, the GUI may display on the controller various diagnostic and monitoring information. As non-limiting examples, the GUI may display electric motor or the turbine temperature, fluid levels, and pump revolutions per minute.

Referring to FIG. 8, a mobile pump system 82. The mobile pump system 82 may include a trailer 84 attachable to a vehicle for moving the trailer 84 to various locations. The mobile pump system 82 may include a controller 86 mounted on the trailer 84, the controller 86 in electrical communication with other components of the mobile pump system 82 (e.g., an electrical transformer 88, a variable frequency drive 90, a heat exchanger, an electric motor 94, a pump 96, a secondary pump 98, and a secondary electric motor 100). The controller 86 may communicate control signals to the other components to cause the other components to perform a predetermined action (e.g., activating or deactivating a component, changing a pump rate, changing a heat exchanger temperature, and the like).

The mobile pump system 82 may include an electrical transformer 88 mounted on the trailer 84. The electrical transformer 88 may increase or decrease a voltage from an external power source for use by one of the components of the mobile pump system 82. This may allow components of the mobile pump system 82 to be powered by an external power source not included on the trailer 84 by electrically connecting the external power source to the transformer 88, which may be electrically connected to the other components.

The mobile pump system 82 may include the variable frequency drive 90 mounted on the trailer 84. The variable frequency drive 90 may include an electro-mechanical drive system to control motor speed and/or torque of the electric motor 94 by varying motor input frequency and/or voltage.

The mobile pump system 82 may include the heat exchanger 92 mounted on the trailer 84 to regulate temperature of at least one of the other components (e.g., the electric motor 94 and/or the pump 96), such that the component can operate more efficiently. The heat exchanger 92 may function as a cooler to prevent a component of the mobile pump system 82 from overheating.

The mobile pump system 82 may include the electric motor 94 mounted on the trailer 84, the electric motor 94 as previously described herein. The mobile pump system 82 may also include the pump 96 a, 96 b (a single or multiple pumps may be included) mounted on the trailer 84. The pump 96 a, 96 b may include the features previously described herein in connection with pump 48. The pump 96 a, 96 b may be driven by the electric motor 94.

With continued reference to FIG. 8 and referring to FIG. 11, the mobile pump system 82 may include a secondary pump 98 and/or a secondary motor 100 (e.g., an electric motor) mounted on the trailer 84. The secondary pump 98 may include a triplex pump. The secondary pump 98 may be configured for pumping fluid at higher pressure compared to the pump 96 a, 96 b of the mobile pump system 82. The secondary pump 98 may be selectively activated in situations in which the mobile pump system 82 is required to operate at a higher pressure. The secondary pump 98 may be isolated from the pump 96 a, 96 b of the mobile pump system. The secondary motor 100 may drive the secondary pump 98. The pump 96 a, 96 b and/or the secondary pump 98 may be in fluid communication with the wellbore 12 (see FIG. 2).

Referring to FIG. 9, a mobile pump system 102 may include any of the components discussed in connection with the mobile pump system 82 from FIG. 8 and may include any additional or alternative components as hereinafter described. The trailer 84 may include a connection portion 104 configured to engage with an engagement portion of a cab (e.g., a fifth wheel). The connection portion 104 may engage with a cab, such that the mobile pump system 102 may be transported by the cab to various locations, such as to and from a production site.

The mobile pump system 102 may include an inlet filter silencer 106 mounted on the trailer 84 to reduce noise emitted by any of the components included in the mobile pump system 102.

The mobile pump system 102 may include a turbine 108 a, 108 b (a single or multiple turbines may be included) mounted on the trailer 84 and connected to the pump 96 a, 96 b. The turbine 108 a, 108 b may be enclosed in a housing. The turbine 108 a, 108 b may be an on-board (on the trailer 84) turbine to generate power on the trailer 84 for driving the pumps 96 a, 96 b. The turbine 108 a, 108 b may be directly coupled to the pump 96 a, 96 b via a gearbox 110 a, 110 b (a single or multiple gearboxes may be included), which may include gear reduction components. The turbine 108 a, 108 b may be powered by using field gas (e.g., natural gas) introduced to the turbine to spin the turbine blades to create power to rotate the pump 96 a, 96 b. The power generated by the turbine 108 a, 108 b may drive the pump 96 a, 96 b. The turbine 108 a, 108 b may be included in the mobile pump system 102 in addition to or in lieu of the electric motor 94 a, 94 b shown in the mobile pump system 82 shown in FIG. 8.

Referring to FIG. 10, a mobile pump system 112 may include all of the components from the mobile pump system 102 of FIG. 9 with the following additions or alterations. The mobile pump system 112 may include a fuel tank 114 (or multiple fuel tanks) mounted on the trailer. The fuel tank 114 may include any type of fuel suitable to fuel any of the components of the mobile pump system 112. Non-limiting examples of suitable fuels for the fuel tank 114 include compressed natural gas (CNG), liquefied natural gas (LNG), diesel fuel, gasoline, propane, butane, and other suitable hydrocarbons and the like. The fuel tank 114 may be in fluid communication with any of the components of the mobile pump system 112 capable of being fueled by the fuel contained in the fuel tank 114. The fuel tank 114 may include any pumps, pipes, hoses, and/or valves required to carry the fuel to the relevant components of the mobile pump system 112.

The fuel tank 114 may be used as a backup fuel supply in the event of a fuel supply interruption. A fuel supply interruption may include the interruption of field gas (e.g., natural gas supplied directly from the production site at which the mobile pump system 112 is located) to the mobile pump system 112. Inclusion of the fuel tank 114 on the trailer 84 allows the mobile pump system 112 to continue operation even in the event of such a fuel supply interruption, without the deployment of an emergency backup power supply to the production site.

The mobile pump system 112 may include a conditioning system 116 configured to condition the gas from the fuel tank 114 or the field gas supplied to the mobile pump system 112. The conditioning system 116 may include a gas heater to drop out solids and/or water from the gas and return it to the supply line. The conditioning system 116 may include at least one filter to filter out impurities in the fuel that could cause the system to malfunction.

Although the invention has been described in detail for the purpose of illustration based on what is currently considered to be the most practical and preferred embodiments, it is to be understood that such detail is solely for that purpose and that the invention is not limited to the disclosed embodiments, but, on the contrary, is intended to cover modifications and equivalent arrangements that are within the spirit and scope of the appended claims. For example, it is to be understood that the present invention contemplates that, to the extent possible, one or more features of any embodiment can be combined with one or more features of any other embodiment. 

The invention claimed is:
 1. A mobile pump system comprising: a trailer movable by a vehicle; and a pump mounted to the trailer, the pump configured to pump a fluid, wherein the pump comprises an electrically-driven motor mounted to the trailer or is turbine powered by a turbine mounted to the trailer.
 2. The mobile pump system of claim 1, wherein the pump is configured to pump the fluid into a wellbore at a tie-in point upstream of a wellhead of the wellbore.
 3. The mobile pump system of claim 1, wherein the fluid comprises water and/or a chemical additive.
 4. The mobile pump system of claim 1, wherein the pump comprises an auger or impeller configured to move the fluid.
 5. The mobile pump system of claim 1, wherein the pump is not permanently installed at a site for performing a pressure pumping application.
 6. The mobile pump system of claim 1, wherein the electrically-driven motor is fueled by a battery, natural gas, diesel fuel, or gasoline.
 7. The mobile pump system of claim 2, wherein the pump is configured to adjust a flow rate of the pump by 1/10th of a bpm.
 8. The mobile pump system of claim 1, wherein the pump is in fluid communication with a wellbore.
 9. The mobile pump system of claim 1, wherein the turbine is operated using field gas.
 10. The mobile pump system of claim 1, comprising a plurality of pumps mounted to the trailer, wherein each pump comprises an electrically-driven motor mounted to the trailer or is turbine powered by a turbine mounted on the trailer.
 11. The mobile pump system of claim 1, further comprising a controller configured to remotely control the pump.
 12. The mobile pump system of claim 11, wherein the controller comprises a portable computing device.
 13. The mobile pump system of claim 1, wherein the pump is configured to pump the fluid at a flow rate as low as 0.1 bpm.
 14. The mobile pump system of claim 1, wherein the turbine comprises a direct coupled gear connection.
 15. A method for performing a pressure pumping application comprising: providing a mobile pump system comprising: a trailer movable by a vehicle; and a pump mounted to the trailer, the pump configured to pump a fluid, wherein the pump comprises an electrically-driven motor mounted to the trailer or is turbine powered by a turbine mounted to the trailer.
 16. The method of claim 15, further comprising: pumping the fluid from a fluid container into a wellbore using the pump to move the fluid from the fluid container into the wellbore.
 17. The method of claim 16, further comprising: positioning a plug in a lateral of the wellbore using the fluid pumped into the wellbore.
 18. The method of claim 15, wherein the pump is configured to pump the fluid into the wellbore at a tie-in point upstream of a wellhead of the wellbore.
 19. The method of claim 15, wherein the pump is configured to adjust a flow rate by 1/10th of a bpm.
 20. The method of claim 15, wherein the pump is configured to pump the fluid at a flow rate as low as 0.1 bpm. 